Steam injection techniques, such as steam stimulation and steam flooding, have been used to recover immobile heavy oils and to enhance the oil recovery from older wells where the natural field pressures are too low for unassisted production. They are designed to reduce the reservoir flow resistance by reducing the viscosity of the crude.
These techniques involve injection into the well of a high temperature wet steam in cycles of thousands of cubic meters at a time. Wet steam is a mixture of steam and varying amount of hot liquid water, the quality of wet steam generally ranges from 35% to 80%. Because of the density difference between the two phases of the wet steam, the vapor phase preferentially enters the upper part of the injection interval and the liquid phase preferentially enters the lower part.
When groundwater, river water, or lake water is used as feedwater to generate wet steam, the liquid water phase is generally basic (having a pH in excess of 11) and the vapor phase of the wet steam, when condensed, is acidic (having a pH of about 4.0 to 4.5). This partitioning is due to the bicarbonate contained in the source water decomposing to CO.sub.2 and OH.sup.-, as shown in Equation 1 below: ##STR1## The CO.sub.2 is volatile and enters the vapor phase, which produces a low pH in the liquids condensed from the vapor phase. The OH.sup.- ion enters the liquid phase and causes a high pH in the liquid phase.
Associated with using these wet steams in steam injection is the problem of silica dissolution. Coupled with high fluid temperatures, both the liquid phase and the liquids from the condensed vapor phase are capable of rapidly dissolving reservoir rocks, such as sandstone, carbonate, diatomite, porcellanite and the like. For pH values above 11.0 and temperatures above 177.degree. C., the silica and silicate dissolution rates are orders of magnitude higher than at neutral/ambient conditions. Also, because the reactions for dissolving siliceous reservoir rocks are base consumers, the liquid pH decreases rapidly as the fluid moves away from the wellbore, causing the dissolution reactions and solubility to diminish rapidly and causing the reaction products downstream (such as aluminosilicates and other metal silicates) to precipitate in the pores. This precipitation decreases the formation permeability and decreases well injectivity.
This problem of silica dissolution was addressed in U.S. Pat. Nos. 4,475,595; 4,572,296; and 4,580,633. All three of those patents are incorporated herein by reference for all purposes. U.S. Pat. No. 4,475,595 discloses adding an ammonium inhibitor to the feedwater or to the wet steam. U.S. Pat. No. 4,572,296 discloses adding an ammonium inhibitor and a compound which hydrolyzes in steam, providing a buffering effect in the liquid phase to prevent excessive pH reduction. U.S. Pat. No. 4,580,633 discloses adding an ammonium inhibitor and an organosilicon compound. In each case, the amount of added ammonium inhibitor is determined by the bicarbonate concentration of the steam.
Also associated with using these wet steams is the problem of permeability damage of hydrocarbon formations containing clay. Formations that contain clay minerals are susceptible to water-rock interactions that cause the clay to disperse and migrate. When they move downstream, they tend to bridge in pore constrictions to form miniature filter-cakes throughout the pore network. This can decrease steam injectivity in the lower interval where liquid water is injected and also in the upper interval where vapor phase condensation takes place. In some cases, clay structural expansion may contribute to this decrease in permeability.
U.S. Pat. No. 4,549,609 discloses an attempt to solve the problem of permeability damage by injecting an ammoniacal nitrogen-containing compound. U.S. Pat. No. 4,549,609 is incorporated herein by reference for all purposes. Since the ammoniacal nitrogen-containing compound stays in the vapor phase of the wet steam, the method disclosed in U.S. Pat. No. 4,549,609 fails to prevent permeability damage in those areas exposed to the liquid phase. Also, the amount of ammoniacal nitrogen-containing compound that can be added without acidic corrosion of the well pipe is limited by the bicarbonate concentration found in the feedwater.
U.S. Pat. No. 4,476,930 discloses a method of inhibiting scale and corrosion in the vapor phase but fails to address the problem of corrosion in the liquid water phase of wet steam caused by adding ammoniacal nitrogen-containing compound.